Additive management system

ABSTRACT

A system including an additive management system configured to oversee hydrate formation in a hydrocarbon extraction system, the additive management system including a flow meter configured to measure a fluid flow rate, a first sensor configured to measure at least one of a fluid property and an environmental condition, and a chemical injection device configured to inject a hydrate inhibitor into a fluid flow.

CROSS REFERENCE TO RELATED APPLICATION

This application claims priority to and benefit of U.S. ProvisionalApplication No. 62/069,729, entitled “Monoethylene Glycol InjectionControl System”, filed Oct. 28, 2014, U.S. Provisional Application No.62/144,178, entitled “Additive Management System,” filed Apr. 7, 2015,U.S. Provisional Application No. 62/186,050, entitled “AdditiveManagement System,” filed Jun. 29, 2015, and U.S. ProvisionalApplication No. 62/173,750, entitled “Method and System for Measuringthe Injection Rate of a Chemical in a Fluid Flow Stream,” filed Jun. 10,2015, the disclosures of which are herein incorporated by reference intheir entireties for all purposes.

BACKGROUND

This section is intended to introduce the reader to various aspects ofart that may be related to various aspects of the present invention,which are described and/or claimed below. This discussion is believed tobe helpful in providing the reader with background information tofacilitate a better understanding of the various aspects of the presentinvention. Accordingly, it should be understood that these statementsare to be read in this light, and not as admissions of prior art.

Hydrate formation in hydrocarbon extraction operations is an industrywide concern. Hydrates are formations of ice and gas that may form dueto high pressures and low temperatures in hydrocarbon extractionenvironments. In order to block hydrate formation, a variety of hydrateinhibitors are used, such as mono-ethylene glycol. These hydrateinhibitors may block hydrate formation by lowering the freezing point ofwater. Unfortunately, hydrate inhibitors may be used excessively toprevent hydrate formation, which unnecessarily increases the cost ofhydrocarbon extraction operations.

BRIEF DESCRIPTION OF THE DRAWINGS

Various features, aspects, and advantages of the present invention willbecome better understood when the following detailed description is readwith reference to the accompanying figures in which like charactersrepresent like parts throughout the figures, wherein:

FIG. 1 is a schematic view of an embodiment of a hydrocarbon extractionsystem with an additive management system;

FIG. 2 is a schematic view of an embodiment of an additive managementsystem;

FIG. 3 is a schematic view of an embodiment of an additive managementsystem coupled to a wellhead system;

FIG. 4 is a schematic view of an embodiment of an additive managementsystem coupled to a wellhead system;

FIG. 5 is a schematic view of an embodiment of an additive managementsystem coupled to a wellhead system;

FIG. 6 is a cross-sectional view of an embodiment of a tubing hanger ofa hydrocarbon extraction system including a sensor;

FIG. 7 is a flow diagram of a method for controlling hydrate formationof a hydrocarbon extraction system; and

FIG. 8 is a flow diagram of a method for controlling a ratio of aninjected chemical to water in a fluid flow.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

One or more specific embodiments of the present invention will bedescribed below. These described embodiments are only exemplary of thepresent invention. Additionally, in an effort to provide a concisedescription of these exemplary embodiments, all features of an actualimplementation may not be described in the specification. It should beappreciated that in the development of any such actual implementation,as in any engineering or design project, numerousimplementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which may vary from one implementation toanother. Moreover, it should be appreciated that such a developmenteffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

The present disclosure is directed to embodiments of an additivemanagement system configured to determine and monitor one or moreconditions of a hydrocarbon extraction system, such as a hydratecondition (e.g., hydrate formation). In order to determine and monitorthe hydrate condition, the additive management system includes acontroller that receives feedback (e.g., data) from one or several flowmeters, sensors, chemical injection metering valves, etc. of thehydrocarbon extraction system. The controller or another device (e.g.,computer) uses the feedback in algorithms, modeling programs, and/orlookup tables to determine the hydrate condition. For example, thecontroller may determine a likelihood of hydrate formation based on ananalysis of the feedback.

Additionally, in certain embodiments, the additive management system maybe configured to provide recommendations to a user based on the hydratecondition (e.g., hydrate formation is likely to occur) to reduce orblock hydrate formation. For example, the additive management system mayprovide recommendations to adjust an amount or flow rate of an injectedhydrate inhibitor. In some embodiments, the additive management systemmay automatically adjust an amount or flow rate of an injected hydrateinhibitor to reduce or block hydrate formation. Furthermore, theadditive management system may enable precise and/or targeted monitoringand/or control of hydrate formation throughout the hydrocarbonextraction system. In particular, the additive management system mayprovide recommendations and/or adjustments for the hydrate inhibitorinjection that are specific for and/or tailored for one or more specificlocations in the hydrocarbon extraction system. For example, theadditive management system may be configured to distribute hydrateinhibitor (or another injected chemical)

Further, in some embodiments, the additive management system may beconfigured to inject a chemical into a fluid flow of the hydrocarbonextraction system and to determine a ratio of the injected chemical torelative water in the fluid flow. For example, the additive managementsystem may inject one or more chemicals, such as hydrate inhibitors(e.g., thermodynamic inhibitors and/or kinetic inhibitors), pHmodifiers, and/or scale inhibitors. The additive management system maydetermine the ratio of the injected chemical relative to water based atleast in part on feedback from one or more optical sensors, feedbackfrom one or more conductivity sensors, or a combination thereof.Additionally, the additive management system may be configured toprovide recommendations to adjust the flow rate and/or amount of theinjected chemical or to automatically adjust the flow rate and/or amountof the injected chemical based on the ratio of the injected chemicalrelative to water. For example, the additive management system maycompare the ratio to a threshold (e.g., above a lower threshold or belowan upper threshold) or threshold range (e.g., between upper and lowerthresholds) and may provide recommendations to adjust or mayautomatically adjust the flow rate and/or amount of the injectedchemical based on the comparison.

FIG. 1 is a schematic view of an embodiment of a hydrocarbon extractionsystem 10 with an additive management system 12 that determines andmonitors one or more parameters or conditions of the hydrocarbonextraction system 10. For example, as described in more detail below,the additive management system 12 may determine or monitor a hydratecondition (e.g., hydrate formation) and/or a ratio or proportion of achemical (e.g., a hydrate inhibitor) relative to water in a fluid flow.Additionally, as described in more detail below, the additive managementsystem 12 may provide recommendations to a user, monitoring system, orcontrol system relating to recommended adjustments for one or moreparameters of the hydrocarbon extraction system 10 and/or mayautomatically adjust one or more parameters of the hydrocarbonextraction system 10 based on the determined parameters and conditionsof the hydrocarbon extraction system 10 (e.g., via a control system).Further, the additive management system 12 may enable precise and/ortargeted monitoring and/or control of parameters and conditionsthroughout the hydrocarbon extraction system 10. In order to monitorand/or control the one or more parameters and/or conditions of thehydrocarbon extraction system 10, the additive management system 12 mayinclude sensors 14 (e.g., conductivity probes, solid particulatesensors, temperature sensors, pressure sensors, optical sensors,salinity sensors, water sensors, etc.), chemical injection meteringvalves (CIMV) 16, hydrate inhibitor regeneration systems 18, flow meters20 (e.g., wet-gas flow meter, multi-phase flow meter), fluid controldevices 22, and control systems 24.

As illustrated, the hydrocarbon extraction system 10 may include one ormore wellhead systems 26 with a wellhead 28 coupled to a production tree30 (e.g., Christmas tree). The wellhead systems 26 couple to a well 32that enables hydrocarbon extraction (e.g., oil and/or natural gas) froma subterranean reservoir 34. As the hydrocarbons exit the well 32, thewellhead system 26 may direct the hydrocarbons to the surface throughrisers 36 for collection and/or processing at a rig 38 or shorefacility. In some embodiments, multiple wells 32 may be part of thehydrocarbon extraction system 10. These wells 32 and wellhead systems 26may couple to a manifold 40 with a jumper system 42 (e.g., jumpercables, pipes, etc.). Accordingly, the rig 36 or shore facility may thencouple to the manifold 40 enabling fluid communication with multiplewells 32.

During extraction operations, additional substances (e.g., water andsediment) may flow out of the wells 32 with the hydrocarbon fluid flow.As the water moves with the hydrocarbons, water (e.g., freezing water)and natural gas components may combine to form hydrates due to highpressures and low temperatures in the hydrocarbon extractionenvironment. However, as described below, the additive management system12 may monitor a hydrate condition (e.g., hydrate formation) of thehydrocarbon extraction system 10 and may reduce, block, or inhibitformation of the hydrates by injecting hydrate inhibitors (e.g.,mono-ethylene glycol, methanol, kinetic hydrate inhibitors,anti-agglomerates, etc.) in the hydrocarbon extraction system 10.

As illustrated, in some embodiment of the disclosure, the additivemanagements system 12 includes in some embodiment of the disclosure, onemore CIMVs 16 that inject one or more chemicals into the fluid flowcoming out of the wells 32. For example, one or more CIMVs 16 may injecthydrate inhibitors (e.g., mono-ethylene glycol, methanol, kinetichydrate inhibitors, thermodynamic inhibitors, anti-agglomerates), pHmodifiers, and/or scale inhibitors. In some embodiments, each wellheadsystem 26 (e.g., each branch of the Christmas tree 30 and/or eachwellhead 28) may include a respective CIMV 16 for chemical injection. Incertain embodiments, the manifold 40 may also include one or more CIMVs16 that inject chemicals. In some embodiments, hydrocarbon extractionsystem 10 may include CIMVs 16 in one or more of the wellhead systems26, the riser 36, the manifold 40, and/or other locations in thehydrocarbon extraction system 10.

By including CIMVs 16 in each of the wellhead systems 26 and/or at otherlocations in the hydrocarbon extraction system 10, the additivemanagement system 12 is able to tailor/control (e.g., provide anappropriate amount—not too much, not too little of) the flow ofchemicals (e.g., hydrate inhibitors) in different areas of thehydrocarbon extraction system 10. That is, the additive managementsystem 12 may be configured to control a plurality of CIMVs 16, whichmay be disposed in different locations (e.g., different wellhead systems26, the riser 36, the manifold 40, etc.) of the hydrocarbon extractionsystem 10, and the additively management system 12 may be configured tocontrol two or more CIMVs 16 or each CIMV 16 of the plurality of CIMVs16 differently to provide a differential distribution of chemicals atthe various locations. For example, the additive management system 12may cause a first CIMV 16 to inject a first amount and/or first flowrate of a chemical and may cause a second CIMV 16 to inject a secondamount and/or second flow rate of a chemical that is different from thefirst amount and/or first flow rate. Further, as will be described inmore detail below, the additive management system 12 may monitor hydrateformation for one or more locations of the hydrocarbon extraction system10 and may determine an amount and/or flow rate of hydrate inhibitor toinject using each CIMV 16 of the one or more locations, and the amountand/or flow rate of the hydrate inhibitor may be specific for and/oroptimized for the particular location. For example, some wells 32 mayproduce or have higher concentrations of water than other wells 32. Inresponse, the additive management system 12 may control one or moreCIMVs 16 to increase hydrate inhibitor injection at wellhead systems 26that experience significant water flow, while controlling one or moredifferent CIMVs 16 to reduce hydrate inhibitor injection at wellheadsystems 26 that produce small amounts of water. Moreover, the additivemanagement system 12 may account for environmental conditions thatenable hydrate formation such as temperature, pressure, and salinity.For example, a first well 32 that is at a lower temperature and/orhigher pressure than a second well 32 may receive more hydrate inhibitorinjection than the second well 32, because the temperatures and/orpressures at the first well 32 are more likely to produce hydrates. Inother words, the additive management system 12 may control one or moreCIMVs 16 to increase hydrate inhibitor injection at wells 32 thatexperience environmental conditions favorable to hydrate formation(e.g., low temperatures and/or high pressures) and/or may control one ormore CIMVs 16 to reduce hydrate inhibitor injection at wells 32 that donot.

As explained above, the additive management system 12 may include avariety of sensors 14 (e.g., conductivity probes, solid particulatesensors, temperature sensors, pressure sensors, optical sensors,salinity sensors, water sensors, etc.) and flow meters 20 (e.g., wet-gasflow meters, multi-phase flow meters). The sensors 14 may measure one ormore conditions and/or parameters of the hydrocarbon extraction system10. For example, as will be described in more detail below, the sensors14 may measure and/or generate feedback relating to temperature,pressure, salinity, conductivity, electromagnetic radiation, attenuationof one or more wavelengths of light, water content (e.g., water cut) ina fluid flow, or any other suitable parameter. Additionally, the flowmeters 20 may measure the flow rate of a fluid (e.g., flow). In someembodiments, the multi-phase flow meters 20 may measure the fullthree-phase performance over the entire gas volume fraction (GVF) andwater liquid ratio (WLR) ranges.

The sensors 14 and the flow meters 20 may be placed in differentlocations in the hydrocarbon extraction system 10. For example, in someembodiments, the sensors 14 and/or the flow meters 20 may be disposed inone or more of the wellhead systems 26 (e.g., each wellhead system 26),the manifold 40, the riser 36, the pipes of the jumper system 42, and/orother locations in the hydrocarbon extraction system 10. In certainembodiments, the sensors 14 and/or flow meters 20 may be mounted on apipe section downstream of a bend, change in cross-sectional area, orother point to facilitate a liquid rich area. In some embodiments, atleast one sensor 14 and/or at least one flow meter 20 may be disposedproximate to (e.g., upstream and/or downstream of) each CIMV 16.

By placing the sensors 14 and the flow meters 20 about differentlocations of the hydrocarbon extraction system 10, the additivemanagement system 12 may measure or determine parameters and/orconditions in the hydrocarbon extraction system 10 at each location andmay enable the control systems 24 to accurately control injection of oneor more chemicals (e.g., hydrate inhibitors) at each location based onthe parameters and/or conditions at the respective location. That is,the amount and/or flow rate of chemical injected may be individualizedand/or specific for each CIMV 16 and/or for each desired location of thehydrocarbon extraction system 10 (e.g., each wellhead system 26, theChristmas tree 30, the riser 36, the manifold 40, the jumper system 42,or any combination thereof) based on the parameters and/or conditions ina region proximate to each CIMV 16 and/or at each desired location. Forexample, in some embodiments, the control systems 24 may use feedback(e.g., signals) from the sensors 14 and/or the flow meters 20 todetermine a hydrate condition for one or more locations (e.g., eachlocation) having the sensors 14 and/or flow meters 20, and the controlsystems 24 may determine an amount and/or flow rate of hydrate inhibitorto inject using one or more CIMVs 16 (e.g., each CIMV 16) based at leastin part on the hydrate condition for the location proximate to therespective CIMV 16.

FIG. 2 is a schematic view of an embodiment of an additive managementsystem 12. As illustrated, the additive management system 12 includesone or more control systems 24 that communicate with and/or controlvarious sensors 14, flow meters 20, flow control device 22 (e.g.,choke), CIMVs 16, and hydrate inhibitor regeneration systems 18. As willbe explained in detail below, the control system (e.g., controller) 24includes one or more processors 60 that execute instructions stored byone or more memories 62 (e.g., tangible, non-transitory memory devices)to control the additive management system 12. During operation, thecontroller 24 may receive feedback from the various sensors 14, such asone or more pressure sensors 64, one or more temperature sensors 66, oneor more conductivity probes (e.g., conductivity sensors) 68, and/or oneor more optical sensors 70. In some embodiments, the pressure sensor 64and the temperature sensor 66 may be combined (e.g., a pressure andtemperature transmitter (PTTx)). Additionally, the controller 24 mayreceive feedback from the various flow meters 20 (e.g., wet-gas flowmeter, multi-phase flow meter). The controller 24 may be operativelycoupled to the sensors 14 and the flow meters 20 via any suitablecommunication link, such as, for example, RS-422, RS-435, RS-485,Ethernet, controller area network (CAN) (e.g., CAN bus, CANopen),optical fibers, and/or wireless communication.

The controller 24 may determine measurement data (e.g., real-time orsubstantially real-time measurement data) based on the feedback from thesensors 14 and/or the feedback from the flow meters 20. For example, themeasurement data may include one or more conditions (e.g., environmentalconditions) of the hydrocarbon extraction system 10, such as pressureand/or temperature. Additionally, the measurement data may include oneor more flow characteristics (e.g., flow parameters) of a fluid flow inthe hydrocarbon extraction system 10, such as flow rate (e.g. mass flowrate), fluid density, salinity, composition, concentration, and soforth. In particular, the controller 24 may determine flowcharacteristics of the process fluid (e.g., the hydrocarbon flow)upstream of a chemical injection point and/or flow characteristics ofthe process fluid downstream of a chemical injection point after mixingwith the injected chemical. For example, as will be described below inFIGS. 3-5, the additive management system 12 may include sensors 14and/or flow meters 20 that are disposed upstream and/or downstream of aCIMV 16. In some embodiments, the controller 24 may use the feedbackfrom the upstream and the downstream sensors 14 and/or flow meters 20 todetermine one or more flow parameters. For example, the controller 24may compare measurements upstream and downstream to determine a ratio ofan injected chemical relative to water, content of water, etc.

Further, it should be noted that the controller 24 may determine flowcharacteristics for one or more components of a fluid flow. For example,the fluid flow may include water, oil, gas, hydrogen sulfide, carbondioxide, nitrogen, salts, and/or one or more injected chemicals (e.g.,hydrate inhibitors, pH modifiers, scale inhibitors, etc.). In someembodiments, the controller 24 may determine the flow rate (e.g., massflow rate) and/or fluid density for one or more components of the fluidflow.

In certain embodiments, the controller 24 may determine an amount,proportion, percentage, or concentration of one or more components inthe fluid flow relative to the total fluid flow. For example, thecontroller 24 may determine the water content (e.g., water cut) in thefluid flow, which may be a proportion, percentage, or concentration ofwater relative to the fluid flow. Additionally, the controller 24 may beconfigured to determine an injected chemical content in the fluid flow,which may be a proportion, percentage, or concentration of the injectedchemical relative to the fluid flow. However, it should be appreciatedthat the controller 24 may be configured to determine the percentage ofany suitable component in the fluid flow. In some embodiments, thecontroller 24 may determine the amount (e.g., proportion, percentage, orconcentration) of one or more components in the fluid flow relative tothe total fluid flow based on feedback from one or more conductivityprobes 68. For example, the one or more conductivity probes 68 may bemicrowave open-ended coaxial probes. In certain embodiments, the one ormore conductivity probes 68 may be conductivity probes as described inU.S. Pat. No. 6,831,470, which is incorporated by reference in itsentirety herein for all purposes, and the controller 24 may use any ofthe methods and techniques described in U.S. Pat. No. 6,831,470 forprocessing signals from the conductivity probe to determine the amountsof the components in a fluid. For example, in one embodiment, theconductivity probe 68 may generate an alternating current electricalsignal (e.g., a reference signal), which may be reflected by the fluidand detected by the conductivity probe (e.g., reflected signal). Thereflected signal may be compared to the reference signal to determinethe electromagnetic properties of the fluid, which may be used todetermine the amount of one or more components in the fluid flow (e.g.,using one or more algorithms, models, look-up tables, etc.). Forexample, the amplitude attenuation and phase shift between the referencesignal and the reflected signal may be used to derive the complexreflection coefficient of the fluid flow, the fluid conductivity, and/orthe fluid permittivity.

In some embodiments, the controller 24 may determine the amount (e.g.,proportion, percentage, or concentration) of one or more components inthe fluid flow relative to the total fluid flow based on feedback fromone or more optical sensors 70. The optical sensors 70 may be infrared,reflectance-type sensors. In some embodiments, the optical sensors 70may be configured to emit light in the mid-wavelength infrared region,the long-wavelength infrared region, and/or the far-infrared region. Forexample, the optical sensors 70 may be configured to emit one or morewavelengths of light in the range of 2 micrometers (μm) to 50 μm, 2.5 μmto 15 μm, 3 μm to 12 μm, or any other suitable range. In particular, theoptical sensors 70 may be configured to emit light at one or morewavelengths corresponding to absorption peaks of one or more componentsin the fluid. For example, the optical sensor 70 may emit a firstwavelength of light with an absorption peak for water, a secondwavelength of light with an absorption peak for an injected chemical(e.g., hydrate inhibitor), a third wavelength of light with anabsorption peak for oil, and so forth. Additionally, the optical sensors70 may be configured to detect light (e.g., in the mid-wavelengthinfrared region, the long-wavelength infrared region, and/or thefar-infrared region) after the emitted light has interacted with thefluid flow. In some embodiments, the optical sensors 70 may beconfigured to emit and detect a plurality of wavelengths of lightcorresponding to various substances in the fluid flow. The controller 24may be configured to determine the amounts of one or more components inthe fluid flow based on the detected light (e.g., reflected light).

Further, by using the conductivity probes 68 and/or the optical probes70, the controller 24 may be configured to detect very low amounts ofwater in the fluid flow. For example, the controller 24 may detect waterin a fluid flow when the water content is between approximately 10 partsper million (ppm) and 500 ppm, 30 ppm and 250 ppm, or 50 ppm and 100ppm. In some situations, the water content may not be measurable (e.g.,water concentration below the level measured by sensors). In thesesituations, the controller 24 may use a modeling program (e.g.,computer-based modeling program, physics-based modeling program) topredict the amount of water flowing through the hydrocarbon extractionsystem 10. Additionally, as will be described in more detail below, incertain embodiments, the controller 24 may determine an amount,proportion, percentage, or concentration of one or more components inthe fluid flow relative to one or more other components in the fluidflow based on feedback from the conductivity probes 68, feedback fromthe optical sensors 70, or both. For example, the controller 24 may beconfigured to determine a ratio of an injected chemical relative towater in the fluid flow.

Additionally, in some embodiments, the controller 24 may be configuredto receive feedback from the sensors 14 and/or the flow meters 20 forverification and/or redundancy purposes. For example, the controller 24may be configured to receive feedback from a conductivity probe 68 andfeedback from an optical sensor 70 that are disposed proximate to oneanother in the same general location in the hydrocarbon extractionsystem 10 such that the flow characteristics of the fluid as it flows bythe conductivity probe 68 are substantially the same as the flowcharacteristics of the fluid as it flows by the optical sensor 70. Inthis manner, if the conductivity probe 68 fails or malfunctions, thecontroller 24 may still determine parameters (e.g., the water contentand injected chemical content) based on feedback from the optical sensor70 and vice versa. In this manner, the conductivity probe 68 and theoptical sensor 70 may be redundant.

Further, the controller 24 may be configured to compare one or moreparameters determined based on feedback from the conductivity probe 68to the same one or more parameters determined based on feedback from theoptical sensor 70 to verify and/or reduce uncertainty in the determinedparameters. For example, the controller 24 may compare a first value ofthe water content and a first value of the injected chemical contentdetermined based on feedback from the conductivity probe 68 to a secondvalue of the water content and a second value of the injected chemicalcontent, respectively, determined based on feedback from the opticalsensor 70. In some embodiments, the controller 24 may determine adifference between a first value of a parameter determined from feedbackfrom the conductivity probe 68 and a second value of the parameterdetermined from feedback from the optical sensor 70 and may compare thedifference to the threshold, which may be stored in the memory 62. Incertain embodiments, the controller 24 may determine a level ofcertainty for the determined measurement based on the comparison. Insome embodiments, the controller 24 may be configured to provide awarning or an alarm in response to a determination that the differenceis greater than the threshold, which may be indicative of an undesirablyhigh level of uncertainty for the determined and/or may be indicative ofa failure or malfunction of the conductivity probe 68 and/or the opticalsensor 70. For example, the controller 24 may be operatively coupled toa user interface 72, which may include a display and/or a speaker, andmay cause the user interface 72 to provide the warning or alarm.

Still further, in some embodiments, each CIMV 16 may include a flowmeter 20 to generate feedback relating to the chemical injection flowrate. In one embodiments, each CIMV 16 may include an ultrasonic flowmeter 20 configured to measure a range of flow rates betweenapproximately 0.5 liters per hour to 26,500 liters per hour, or more. Asnoted above, the controller 24 may control each CIMV 16 to inject achemical at a designated or assigned injection rate. To verify that eachCIMV 16 is injecting the chemical at its respective assigned injectionrate, the controller 24 may compare the assigned injection rate to aninjection rate determined based on feedback from the flow meter 20 ofthe respective CIMV 16 to confirm or verify the actual injection rate ofthe chemical. In some embodiments, the controller 24 may provide awarning or alarm (e.g., via the user interface 72) if a differencebetween the assigned injection rate and the determined injection rate isgreater than a threshold, which may be stored in the memory 62. Forexample, a difference that is greater than the threshold may beindicative of a failure or malfunction of the CIMV 16.

As noted above, the sensors 14 and the flow meters 20 may be disposedabout in a plurality of different locations of the hydrocarbonextraction system 10. To enable targeted monitoring and/or control ofparameters and conditions of the hydrocarbon extraction system 10 in thedifferent locations, the controller 24 may be configured to associatefeedback from each sensor 14 and feedback from each flow meter 20 withthe location of the respective sensor 14 or flow meter 20. For example,in some embodiments, each sensor 14 and each flow meter 20 may becoupled to the controller 24 via an individual channel or a separatepinout in a multibus, and the controller 24 may determine the locationof the feedback from each sensor 14 and each flow meter 20 based on thechannel or pinout from which the controller 23 received the feedback. Incertain embodiments, one or more of the sensors 14 and one or more ofthe flow meters 20 may include a tag or memory device 73, which may beconfigured to store information about the respective sensor 14 or flowmeter 20. For example, the tag or memory device 73 may storeidentification information (e.g., an identification number, a uniqueidentification number, etc.) and/or location information. The sensors 14and the flow meters 20 may be configured to transmit the informationfrom the tag or memory device 73 to the controller 24 with the generatedfeedback, and the controller 24 may determine the location of thesensors 14 and the flow meters 20, and therefore the generated feedback,based on the information. In some embodiments, the memory 62 may store alookup table or database linking the information to the respectivelocation, and the controller 24 may access the lookup table or databaseusing the information to determine the location. It should beappreciated that the above-mentioned examples are not intended to belimiting, and any suitable techniques for determining the location ofthe sensors 14 and the flow meters 20 may be used.

The controller 24 may use the determined measurement data to determineone or more hydrate conditions for the hydrocarbon extraction system 10.In some embodiments, the controller 24 may determine a plurality ofhydrate conditions for a plurality of locations about the hydrocarbonextraction system 12 using the measurement data from the plurality ofsensors 14 and flow meters 20 and the information stored in the tags 73of the sensors 14 and flow meters 20. For example, the controller 24 maydetermine a hydrate condition for each wellhead system 26, a hydratecondition for one or more locations about the riser 36 (e.g., atdifferent depths along the riser 36), a hydrate condition for themanifold 40, a hydrate condition for one or more locations about thepipes of the jumper system 42, and so forth.

In order to determine the one or more hydrate conditions (e.g., whetherthe water in the fluid flow will form or is likely to form hydrates),the controller 24 may be configured to use the measurement data with oneor more modeling programs, algorithms, hydrate formation curves, look-uptables, databases, or any combination thereof. For example, thecontroller 24 may include one or more modeling programs, algorithms,hydrate formation curves, look-up tables, and/or databases stored in thememory 62 that the processor 60 executes or accesses to determinehydrate formation. In some embodiments, the controller 24 maycommunicate with another computer(s) 74 that include one or moreprocessors 76 and one or more memories 78 that run the modelingprograms, algorithms, hydrate formation curves, look-up tables, and/ordatabases. In some embodiments, the computer 74 may receive themeasurement data directly from the sensors 14, flow meters 20, etc.and/or from the controller 24.

In particular, the modeling programs, algorithms, hydrate formationcurves, look-up tables, and/or databases may predict or estimate thelikelihood of hydrate formation (e.g., the hydrate condition) based ondifferent values of at least one parameter of the hydrocarbon extractionsystem 10. For example, the modeling programs, algorithms, hydrateformation curves, look-up tables, and/or databases may predict orestimate the likelihood of hydrate formation based on one or moreparameters of a hydrocarbon fluid flow, such as temperature, pressure,flow rate (e.g., flow rate of water, flow rate of oil, flow rate ofgas), fluid density, salinity, composition (e.g., relative amounts ofoil, gas, water, carbon dioxide, hydrogen sulfide, nitrogen, hydrateinhibitor, or any other component), water content, and/or hydrateinhibitor content. In some embodiments, the modeling programs,algorithms, hydrate formation curves, look-up tables, and/or databasesmay define one or more boundary conditions for the one or moreparameters such that values of the one or more parameters (e.g., aloneor in combination with other parameters) that meet or violate the one ormore boundary conditions are likely to result in hydrate formation.

In certain embodiments, the memory 62 and/or the memory 78 may store aplurality of modeling programs, algorithms, hydrate formation curves,look-up tables, and/or databases that each predict or estimate thelikelihood of hydrate formation based on a different parameter or adifferent combination of parameters. By way of example, the memory 62may store a first modeling program that estimates the likelihood ofhydrate formation based on temperature, a second modeling program thatestimates the likelihood of hydrate formation based on temperature andpressure, a third modeling program that estimates the likelihood ofhydrate formation based on temperature, pressure, and water content, anda fourth modeling program that estimates the likelihood of hydrateformation based on temperature, pressure, water content, and hydrateinhibitor content. In such embodiments, the controller 24 may beconfigured to select a modeling program, algorithm, hydrate formationcurve, look-up table, and/or database based on the parameters determinedby the controller 24 using the feedback from the sensors 14 and flowmeters 20. For example, the controller 24 may select the second modelingprogram if the controller 24 determines pressure and temperature and mayselect the third modeling program if the controller 24 determinespressure, temperature, and water content. In some embodiments, thememory 62 and/or the memory 78 may also store a level of certainty foreach of the plurality of modeling programs, algorithms, hydrateformation curves, look-up tables, and/or databases, which may increasewith the number of parameters used by the respective modeling program,algorithm, hydrate formation curve, look-up table, or database. That is,the determination of hydrate formation may have a higher level ofcertainty when more information (e.g., more parameters) is used.Further, in some embodiments, the memory 62 may store a plurality ofmodeling programs that model different states of the hydrocarbonextraction system 10. For example, the modeling programs may modelstart-up, steady-state, look ahead scenarios (e.g., planned shut-in,unplanned shut-in, shut down, etc.), among others. Further, in someembodiments, the modeling programs may include a real-time transientproduction simulator configured to enable presentation of flow variablesin real time between points of measurements. In some embodiments, thereal-time transient production simulator can be used for forecasting andproviding what-if scenarios from current conditions, yielding liveestimates of cool-down times, no-touch times, and other information forhydrate management. Further, alarms (e.g., alarms triggered by thereal-time transient production simulator, alarms triggered by themodeling programs, etc.) may be configured to notify control roomoperators of potential operational issues before they occur.

In operation, the controller 24 (or the computer 74) may determine thevalue of at least one parameter of the hydrocarbon extraction system 10based on feedback from at least one sensor 14, feedback from at leastone flow meter 20, or both, and may use the value of the at least oneparameter in at least one modeling program, algorithm, hydrate formationcurve, look-up table, or database to determine the hydrate conditions(e.g., the likelihood of hydrate formation). As noted above, in someembodiments, the controller 24 may select a modeling program, algorithm,hydrate formation curve, look-up table, or database based on theparameters determined by the controller 24. Additionally, if thecontroller 24 determines that hydrate formation is likely, thecontroller 24 may determine an amount and/or flow rate of a hydrateinhibitor to inject to reduce or block hydrate formation. In someembodiments, the controller 24 may use the modeling program, algorithm,hydrate formation curve, look-up table, and/or database to determine theamount and/or flow rate of the hydrate inhibitor to inject based on thehydrate condition. For example, the controller 24 may input one or morevalues of one or more parameters into a modeling program, and themodeling program may output both the hydrate condition and an amountand/or flow rate of hydrate inhibitor to inject based on the hydratecondition.

In some embodiments, the controller 24 may be configured to execute oneor more algorithms to determine an amount and/or a flow rate of hydrateinhibitor to inject based on the hydrate condition. For example, in oneembodiment, the controller 24 may be configured to use the Hammerschmidtequation, which is provided below:

${x = \frac{d \times M \times 100}{K + {d \times M}}},$

where x is the concentration of the hydrate inhibitor in weight percent,d is the depression of the hydrate point in degrees Celsius, M is themolecular weight of the hydrate inhibitor, and K is a dimensionlessconstant for the particular hydrate inhibitor. In particular, thecontroller 24 may determine a desired depression of the hydrate point(i.e., d) to reduce or block hydrate formation based on the determinedhydrate condition, and the controller 24 may determine (e.g., solve for)the concentration of hydrate inhibitor to inject based on the desireddepression of the hydrate point. In some embodiments, the controller 24may determine the flow rate (e.g., mass flow rate) of hydrate inhibitorto inject based on the determined concentration of hydrate inhibitor andthe flow rate (e.g., mass flow rate) of water in the fluid flow. Thehydrate inhibitor may be become diluted after it is injected into thehydrocarbon fluid flow and mixes with other substances, which maydecrease the concentration of the hydrate inhibitor and may decrease theeffectiveness of the hydrate inhibitor. The diluted hydrate inhibitormay be referred to as rich hydrate inhibitor, while the higher purityhydrate inhibitor (e.g., the hydrate inhibitor reclaimed using thehydrate inhibitor regeneration systems 18 and/or the hydrate inhibitorinjected using the CIMVs 16) may be referred to as lean hydrateinhibitor. In some embodiments, x may be the concentration of the richhydrate inhibitor, and the controller 24 may determine the mass flow ofhydrate inhibitor to inject based on the mass flow of water, theconcentration of the rich hydrate inhibitor, and the concentration oflean hydrate inhibitor, which may be known or determined from thehydrate inhibitor regeneration systems 18. For example, the controller24 may determine the mass flow of hydrate inhibitor to inject using thefollowing equation:

${m_{I} = {m_{W} \times ( \frac{x}{x_{L} - x} )}},$

where m_(I) is the mass flow of the hydrate inhibitor (e.g., kg/d),m_(W) is the mass flow of water (e.g., kg/d), x is the concentration ofthe rich hydrate inhibitor (e.g., weight percent), and x_(L) is theconcentration of the lean hydrate inhibitor (e.g., mass percent).

Further, the controller 24 and/or the computer 74 may determine hydratecondition and the amount and/or flow rate of hydrate inhibitor to injectfor a plurality of locations about the hydrocarbon extraction system 10.For example, the controller 24 may determine hydrate condition and theamount and/or flow rate of hydrate inhibitor to inject for each area orregion including a CIMV 16. In some embodiments, the controller 24(e.g., using the modeling programs) may be configured to forecast orextrapolate measurement data (e.g., determined from the sensors 14 andthe flow meters 20) to determine hydrate conditions and/or amountsand/or flow rates of hydrate inhibitor to inject for other locations ofthe hydrocarbon extraction system 10 that do not include the sensors 14and/or the flow meters 20. However, the forecasted or extrapolatedinformation may have a lower level of certainty than the measurementdata, but may be helpful in controlling hydrate conditions throughoutthe entire hydrocarbon extraction system 10 with a limited number ofsensors 14.

If the controller 24 and/or the computer 74 determines that hydrateformation is likely or will be likely in a future scenario, thecontroller 24 and/or computer 74 may advise or warn an operator throughthe user interface 72. In particular, the controller 24 and/or thecomputer 72 may cause the user interface 72 to display an indicationthat hydrate formation is likely and to display a recommended amountand/or flow rate of hydrate inhibitor to inject to reduce or block thehydrate formation. As will be appreciated, in embodiments in which theadditive management system 12 determines a hydrate condition and anamount and/or flow rate of hydrate inhibitor to inject for a pluralityof locations about the hydrocarbon extraction system 10, the userinterface 72 may also display an indication of the location for eachhydrate condition and recommendation for the amount and/or flow rate ofhydrate inhibitor to inject. In some embodiments, the user interface 72may also display a level of certainty for the respective hydratecondition and/or recommended amount and/or flow rate of hydrateinhibitor to inject. For example, the level of certainty may bedetermined by the controller 24 and may be based on a level of certaintyof the modeling program (or hydrate formation curve, look-up table,algorithm, database, etc.) used, as well as any redundant measurements(e.g., feedback from the conductivity probe 68 and feedback from theoptical sensor 70, etc.) used by the controller 24. The operator maythen provide instructions to the additive management system 12 toincrease, start, decrease, and/or stop hydrate inhibitor injectionthrough one or more CIMVs 16. In particular, the operator may provideinstructions to the additive management system 12 to adjust hydrateinhibitor injection through the one or more CIMVs 16 using therecommended hydrate inhibitor injection settings (e.g., flow rate,amount, and/or location) determined by the controller 24 and/or thecomputer 74.

In some embodiments, the additive management system 12 may automaticallyadjust hydrate inhibitor injection based on sensor 14 and flow meter 20feedback. In particular, the additive management system 12 may controlone or more CIMVs 16 to automatically adjust hydrate inhibitor injectionbased on a determined amount and/or flow rate of hydrate inhibitor toinject to reduce or block a determined hydrate condition. Once the CIMVs16 are activated, the controller 24 and/or computer 74 may monitor theamount of hydrate inhibitor injected into the fluid flow and may updatethe modeling programs based on the amount of hydrate inhibitor injected.For example, the controller 24 and/or the computer 74 may continue tomonitor feedback from the sensors 14 and the flow meters 20 to determineupdated hydrate conditions and to determine updated amounts and/or flowrates of hydrate inhibitor to inject. In some embodiments, the modelingprograms may be smart or learning modeling programs that may beconfigured to learn based on historical data.

In some embodiments, the additive management system 12 may also beconfigured to monitor the hydrate inhibitor regeneration system 18.During operation, the hydrate inhibitor regeneration system 18 removeshydrate inhibitor from the fluid flow when it reaches the rig 38. Asnoted above, the concentration of the hydrate inhibitor entering thehydrate inhibitor regeneration system 18 may be rich from dilution withother substances, which reduces the effectiveness of the hydrateinhibitor. Thus, by separating the hydrate inhibitor from the fluidflow, the hydrate inhibitor regeneration system 18 may recover leanhydrate inhibitor that has a higher concentration than the rich hydrateinhibitor, which may reduce the amount of hydrate inhibitor used. Insome embodiments, the hydrate inhibitor regeneration system 18 may beconfigured to determine the concentration of the rich and lean hydrateinhibitor. As noted above, by measuring the concentration (e.g.,strength, potency) of the hydrate inhibitor before and after injection(e.g., rich and lean concentrations), the controller 24 may determinehow much hydrate inhibitor should be injected to block hydrateformation. The controller 24 and/or computer 74 may also receive inputfrom the hydrate inhibitor regeneration system 18 indicating how muchhydrate inhibitor is available for use (e.g., the rich and lean hydrateinhibitor tank volume measurements) and the concentration (e.g.,potency) of the hydrate inhibitor. This information may likewise be fedinto the modeling programs enabling the modeling programs to providefeedback to an operator about whether there is enough hydrate inhibitorfor future hydrate prevention scenarios (e.g., shut down, start up),warn a user to order more hydrate inhibitor, etc.

In some embodiments, the additive management system 12 may include flowcontrol devices 22 (e.g. chokes) that facilitate mixing between thehydrate inhibitor and the fluid flowing out of the well 32. In someembodiments, the controller 24 may receive feedback from a sensor 14and/or flow meter 20 that measures the concentration of hydrateinhibitor. If the measured concentration is more or less than theexpected concentration based on feedback from the CIMV 16, thecontroller 24 may adjust the flow control device 22 to increase mixingbetween the hydrate inhibitor and the fluid flow.

FIG. 3 is a schematic view of an embodiment of the additive managementsystem 12 coupled to a wellhead system 26. As explained above, theadditive management system 12 enables precise and/or targeted control ofthe hydrate formation throughout the hydrocarbon extraction system 10,which reduces the amount of hydrate inhibitor used as well as thehydrate inhibitor infrastructure. Accordingly, FIG. 3 illustrateshydrate inhibitor injection into a specific wellhead system 26.

The additive management system 12 includes sensors 14, a flow meter 20,and a CIMV 16 that couple to a controller 24. In operation, the flowmeter 20 measures the flow rate of fluid exiting the well 32. In someembodiments, the flow meter 20 may be a wet-gas flow meter ormulti-phase flow meter capable of measuring a fluid flow rate as well asthe concentration of water in the fluid flow. In addition, thecontroller 24 receives feedback from additional sensors 14. For example,the additive management system 12 may include a pressure sensor, atemperature sensor, a conductivity probe, a solid particulate sensor,and a salinity sensor among others that couple to the wellhead system26. In some embodiments, the sensor 14 may be a conductivity probe 68capable of measuring the concentrations of one or more components in thefluid flow. For example, in some embodiments, the conductivity probe 68may be configured to measure low concentrations of water in the fluidflow. In certain embodiments, the sensor 14 may be an optical sensor 70,which may be configured to measure the concentrations of one or morecomponents in the fluid flow, such as the concentration of water.Moreover, in some embodiments, the conductivity probe 68, the opticalsensor 70, and/or a wet-gas/multiphase flow meter 20 may be placedbefore the CIMV 16 to block inclusion of the hydrate inhibitor in themeasurement of water content of the fluid flow.

In operation, the controller 24 combines the information from the flowmeter 20 (e.g., wet-gas flow meter, multi-phase flow meter) and thesensors 14 to determine how much hydrate inhibitor should be injectedinto the fluid flow. As explained above, the flow meter 20 measures theflow rate of fluid exiting the well 32 while the sensors 14 measure oneor more environmental conditions (e.g., pressure, temperature, watercontent, salinity, etc.). In some embodiments, the additive managementsystem 12 may include a sensor 14 (e.g., conductivity probe 68 and/oroptical sensor 70) configured to measure low concentrations of water inthe fluid flow. In order to increase accurate measurement of the watercontent, the sensor 14 may be placed upstream from the CIMV 16 to blockinclusion of the hydrate inhibitor in the water content measurement. Insome embodiments, the additive management system 12 may also provideredundant measurement of hydrate inhibitor injection into the fluidflow. For example, the additive management system 12 may receivefeedback from the CIMV 16 as well as a flow meter 20 (e.g., anultrasonic flow meter) to measure the flow rate of the injected hydrateinhibitor. As noted above, the controller 24 may be configured tocompare the flow rate measured by the flow meter 20 to the set injectionrate of the CIMV 16 to determine whether the CIMV 16 is injecting thehydrate inhibitor at the correct rate. The flow meter 20 may be disposedin the CIMV 16, or may be disposed proximate to the CIMV 16 and directlyupstream or downstream of the injected hydrate inhibitor such that theflow meter 20 receives the hydrate inhibitor before the hydrateinhibitor is injected into the fluid flow. In certain embodiments, theadditive management system 12 may also include a sensor 14 (e.g., aconductivity probe 68, an optical sensor 70, etc.) to measure theconcentration of hydrate inhibitor entering the fluid flow. In someembodiments, the flow meter 20 may be configured to measure theconcentration of hydrate inhibitor entering the fluid flow. As explainedabove, by measuring the concentration (e.g., strength, potency) of thehydrate inhibitor before injection, the modeling programs are able todetermine how much hydrate inhibitor should be injected to block hydrateformation. While FIG. 3 illustrates sensors 14 and the flow meter 20coupled to the Christmas tree 30 (e.g., production tree), the sensors 14and flow meter 20 may be coupled to other areas of the wellhead system26 (e.g., wellhead 28, jumper system 42, etc.).

FIG. 4 is a schematic view of an embodiment of the additive managementsystem 12 coupled to a wellhead system 26. The additive managementsystem 12 includes sensors 14, a flow meter 20, and a CIMV 16 thatcouple to a controller 24. In some embodiments, the additive managementsystem 12 may include a sensor 14 (e.g., a conductivity probe 68 and/oran optical sensor 70) downstream of the CIMV 16 to measure one or moreflow parameters of the fluid flow after mixing with a chemical injectedvia the CIMV 16. For example, the conductivity probe 68 and/or anoptical sensor 70 may be configured to determine the water content, thehydrate inhibitor content, or an injected chemical content, as describedabove. In certain embodiments, the conductivity probe 68 and/or theoptical sensor 70 may be configured to generate feedback that may beused by the controller 24 to determine a ratio of an injected chemicalrelative to water in the fluid flow. For example, the conductivity probe68 may measure the electromagnetic properties of the mixed fluid (e.g.,downstream of the CIMV 16) at two different electromagnetic frequencies.The controller 24 may be configured to compare signals from theconductivity probe 68 at each frequency to determine a ratio of aninjected chemical relative to water in the fluid flow based on thefrequency-dependence of the measured electromagnetic properties. Thecontroller 24 may be configured to use one or more algorithms (e.g., tocalculate the fluid conductivity, fluid permittivity, and/or complexreflection coefficient), look-up tables (e.g., including empiricaldata), models, and so forth to derive the ratio of the injected chemicalrelative to water based on the electromagnetic properties. In someembodiments, the controller 24 may compare signals at differentwavelengths (e.g., two or more wavelengths) from the optical sensor 70to determine a ratio of an injected chemical relative to water in thefluid flow. As will be described in more detail below, the controller 24may be configured to adjust the injection rate of an injected chemicalor to provide a recommendation to adjust the injection rate of aninjected chemical to achieve a desired ratio of injected chemical towater in the fluid flow.

FIG. 5 is a schematic view of an embodiment of a section of the additivemanagement system 12 coupled to a wellhead system 26. The additivemanagement system 12 includes sensors 14, a flow meter 20, a flowcontrol device 22, and a CIMV 16 that couple to a controller 24. Asillustrated, the additive management system 12 includes sensors 14upstream and downstream of the CIMV 15. For example, the additivemanagement system 12 may include an upstream conductivity probe 68 and adownstream conductivity probe 68 and/or an upstream optical sensor 70and a downstream optical sensor 70. In this manner, the controller 24may be configured to determine the water content in the fluid upstreamof the CIMV 16, the water content in the fluid downstream of the CIMV16, and the injected chemical content (e.g., the hydrate inhibitorcontent) in the fluid downstream of the CIMV 16. Further, the controller24 may be configured to determine a ratio of an injected chemicalrelative to water in the fluid flow. For example, the controller 24 maydetermine or derive the electromagnetic properties of water based onfeedback (e.g., a first signal) from an upstream conductivity probe 68.Additionally, the controller 24 may be configured to determine or derivethe electromagnetic properties of a water-chemical mixture based onfeedback (e.g., a second signal) from a downstream conductivity probe68. Further, the controller 24 may be configured to compare theelectromagnetic properties of the water with the electromagneticproperties of the water-chemical mixture to determine a ratio ofinjected chemical relative to water. Additionally or alternatively, thecontroller 24 may receive signals at multiple wavelengths from adownstream optical sensor 70, and the controller 24 may analyze thesignals at the multiple wavelengths to determine a ratio of injectedchemical relative to water. For example, the upstream optical sensor 70and/or the downstream optical sensor 70 may each be configured to emitat least a first wavelength corresponding to an absorption peak of waterand a second wavelength corresponding to an absorption peak of theinjected chemical. In some embodiments, the controller 24 may beconfigured to determine the ratio of the injected chemical to waterbased on the measured absorbance at each wavelength, the path lengths ofwater and the injected chemical, and the absorption coefficients ofwater and the injected chemical (e.g., using Beer-Lambert's law).

In some embodiments, the additive management system 12 may include aflow control device 22. As explained above, the flow control devices 22(e.g. chokes) facilitate mixing between the injected chemical (e.g.,hydrate inhibitor) and the fluid flowing out of the well 32. In someembodiments, the controller 24 may use feedback from a sensor 14 (e.g.,the conductivity probe 68 and/or the optical sensor 70) downstream fromthe flow control device 22 to determine whether the injected chemicalhas mixed adequately with the fluid flow. If mixing is inadequate, thecontroller 24 may adjust the flow control device 22 to increase mixingbetween the fluid flow and the injected chemical.

FIG. 6 is a cross-sectional view of an embodiment of a hanger 100 (e.g.,a tubing hanger) of the hydrocarbon extraction system 10. The tubinghanger 100 may include a production bore 102 (e.g., a main bore) and anoutlet passage 104 that branches off from the production bore 102.Additionally, the tubing hanger 100 may include a wireline plug 106configured to seal the production bore 102 above the outlet passageway104. Further, the tubing hanger 100 may include a CIMV 16 configured toinject a chemical into the outlet passageway 104. To measure one or moreproperties of the fluid flow (e.g., water content) upstream of theinjection point, the tubing hanger 100 may include one or more sensors14 (e.g., a conductivity probe 68) upstream of the injection point. Inparticular, a conductivity probe 68 may be disposed within theproduction bore 102. In some embodiments, the conductivity probe 68 maybe disposed within the production bore 102 below the wireline plug 106.However, it should be appreciated that the additive management system 12may include the sensors 14 in any suitable location about the tubinghanger 100, such as in the outlet passageway 104 upstream of the CIMV 16and/or in the outlet passageway 104 downstream of the CIMV 16. Providingsensors 14 in the tubing hanger 100 may be desirable because the sensors14 may be removable or retrievable with the tubing hanger 100.

FIG. 7 is an embodiment of a method 120 for controlling hydrateformation of the hydrocarbon extraction system 10. The method 120 may bea computer-implemented method. For example, one or more steps of themethod 120 may be executed using the controller 24 (e.g., the processor60) and/or the computer 74. The method 120 may include receiving (block122) feedback from one or more sensors 14 and/or one or more flow meters20 disposed in hydrocarbon extraction system 10. Additionally, themethod 120 may include determining (block 124) one or more parametersbased on the feedback. For example, the controller 24 may be configuredto determine one or more parameters of a fluid flow in the hydrocarbonextraction system 10, such as pressure, temperature, flow rate, fluiddensity, composition (e.g., water content, injected chemical content,hydrate inhibitor content, a ratio of an injected chemical to water,etc.), or any other suitable parameter. Further, the method 120 mayinclude determining (block 126) a hydrate condition based on the one ormore parameters. In particular, the controller 24 may estimate thelikelihood of hydrate formation based on the one or more parametersusing the one or more modeling programs, hydrate formation curves,algorithms, database, and/or look-up tables described in detail above.Additionally, the method 120 may include determining (block 128) anamount and/or a flow rate (e.g., mass flow) of a hydrate inhibitor toinject based on the hydrate condition. In particular, the controller 24may determine an amount and/or flow rate of a hydrate inhibitor toinject to reduce or block hydrate formation. The controller 24 maydetermine the amount and/or flow rate using the modeling programs and/orone or more algorithms, as noted above. Further, as noted above, thecontroller 24 may be configured to determine a hydrate condition and anamount and/or flow rate of hydrate inhibitor to inject for a pluralityof locations about the hydrocarbon extraction system 10.

Additionally, in some embodiments, the method 120 may include providing(block 130) an indication of the amount and/or flow rate of hydrateinhibitor to inject. For example, the controller 24 may cause the userinterface 72 to display the indication. In this manner, an operator mayview the recommended injection settings and may manually adjust theCIMVs 16 to the recommended injection settings or may provide inputs tothe controller 12 to adjust the CIMVs 16 to the recommended settings. Incertain embodiments, the method 120 may include adjusting (block 132)the amount and/or flow rate of the hydrate inhibitor to inject. Forexample, the controller 24 may control the CIMVs 16 to adjust the amountand/or flow rate in a closed-loop control. Further, the method 120 maycontinue receiving feedback (block 122), determining parameters (block124), determining the hydrate condition (block 126), and determining anamount and/or flow rate of hydrate inhibitor (block 128).

FIG. 8 is an embodiment of a method 150 for controlling a ratio of aninjected chemical relative to water (e.g., ratio=chemical/water) in afluid flow of the hydrocarbon extraction system 10. The method 150 maybe a computer-implemented method. For example, one or more steps of themethod 150 may be executed using the controller 24 (e.g., the processor60) and/or the computer 74. The method 150 may include determining(block 152) a ratio of an injected chemical relative to water in a fluidflow. In particular, the controller 24 may determine the ratio based atleast in part on two electromagnetic radiation (EMR) signals. Forexample, the controller 24 may receive two EMR signals at two differentfrequencies from a conductivity probe 68 downstream of an injectionpoint (e.g., downstream of a CIMV 16) and may determine the ratio of theinjected chemical relative to water based on a comparison of theelectromagnetic properties in the fluid in the first EMR signal at thefirst frequency and the electromagnetic properties in the fluid in thesecond EMR signal at the second frequency. In some embodiments, thecontroller 24 may receive a first EMR signal from a conductivity probe68 upstream of an injection point and a second EMR signal from aconductivity probe 68 downstream of the injection point, and thecontroller 24 may determine the ratio by comparing electromagneticproperties of the fluid in the first and second EMR signals. Further, insome embodiments, the controller 24 may receive a first EMR signal(e.g., a mid-infrared signal) from an optical sensor 70 upstream of aninjection point and a second EMR signal (e.g., mid-infrared signal) froman optical sensor 70 downstream of the injection point, and thecontroller 24 may determine the ratio based at least in part on theabsorbance of the two EMR signals, the absorption coefficient of theinjected chemical, the absorption coefficient of water. In certainembodiments, the controller 24 may receive EMR signals (e.g.,mid-infrared signals) at multiple wavelengths (e.g., at least twowavelengths) from an optical sensor 70 downstream of an injection point,and the controller 24 may determine the ratio based at least in part onthe absorbance of the EMR signals at the multiple wavelengths, theabsorption coefficient of the injected chemical, the absorptioncoefficient of water. Additionally, in some embodiments, the controller24 may be configured to measure a property of the chemical prior toinjection and may be configured to use the measured property in thedetermination of the ratio. In one embodiment, the controller 24 maymeasure the water content of the injected chemical prior to injection.For example, as noted above, the lean hydrate inhibitor (e.g., MEG) maystill include some water after the regeneration process, so it may bedesirable to determine the water content in the hydrate inhibitor priorto injection.

Additionally, the method 150 may include determining (block 154) whetherthe ratio is within a desired threshold or threshold range. For example,the threshold range may be between approximately 1:1000 and 1000:1,1:500 and 500:1, 1:250 and 250:1, 1:100 and 100:1, 1:75 and 75:1, 1:50and 50:1, 1:25 and 25:1, 1:10 and 10:1, 1:5 and 5:1, or any othersuitable range. In one embodiment, the threshold (e.g., upper thresholdor lower threshold) may be 1:1. In some embodiments, the threshold orthreshold range may be based on the type of injected chemical. By way ofexample, MEG may have a threshold range that is between approximately1:10 and 10:1, and kinetic hydrate inhibitors may have a threshold rangebetween approximately 1:1 and 1:1000. Accordingly, the controller 24 maybe configured to select a threshold range from the memory 62 based onthe type of injected chemical.

Further, in some embodiments, the method 150 may include providing(block 156) an indication to adjust the injected chemical rate inresponse to a determination that the ratio is not within a desiredthreshold or threshold range. For example, the controller 24 may causethe user interface 72 to display the indication. In some embodiments,the controller 24 may determine an amount and/or flow rate of chemicalto inject to achieve the desired ratio, and the controller 24 may causethe user interface 72 to display the recommended injection setting(e.g., amount and/or flow rate). Additionally, in some embodiments, themethod 150 may include adjusting (block 158) the amount and/or flow rateof the injected chemical to achieve the desired ratio. For example, thecontroller 24 may control one or more CIMVs 16 to adjust an amountand/or flow rate of the injected chemical.

While the invention may be susceptible to various modifications andalternative forms, specific embodiments have been shown by way ofexample in the drawings and have been described in detail herein.However, it should be understood that the invention is not intended tobe limited to the particular forms disclosed. Rather, the invention isto cover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the followingappended claims.

1. A system, comprising: an additive management system configured tooversee hydrate formation in a hydrocarbon extraction system, theadditive management system comprising: a first sensor configured togenerate feedback relating to at least one parameter of a fluid flowingthrough the hydrocarbon extraction system; a first chemical injectiondevice configured to inject a hydrate inhibitor into the fluid at afirst location; a controller configured to: receive the feedback fromthe first sensor; determine a likelihood of hydrate formation in thefluid at the first location based on the feedback; determine a flow rateof hydrate inhibitor to inject into the fluid using the first chemicalinjection device based on the likelihood of hydrate formation at thefirst location.
 2. The system of claim 1, wherein the controller isconfigured to control the chemical injection device to inject thehydrate inhibitor at the determined flow rate.
 3. The system of claim 1,comprising a user interface operatively coupled to the controller,wherein the controller is configured to cause the user interface todisplay a recommendation to adjust a flow rate of the hydrate inhibitorto the determined flow rate.
 4. The system of claim 1, wherein the firstsensor is a conductivity probe, and wherein the controller is configuredto determine a proportion of water in the fluid based on feedback fromthe conductivity probe and to determine the likelihood of hydrateformation based on the proportion of water in the fluid.
 5. The systemof claim 4, wherein the conductivity probe is disposed in a hanger ofthe hydrocarbon extraction system upstream from the chemical injectiondevice.
 6. The system of claim 1, wherein the first sensor is configuredto measure temperature and pressure, and wherein the additive managementsystem comprises a second sensor configured to measure a third parameterof the fluid, wherein the controller is configured to determine thelikelihood of hydrate formation based on feedback from the first sensorand feedback from the second sensor.
 7. The system of claim 1, whereinthe additive management system comprises: a second sensor configured togenerate feedback relating to at least one parameter of the fluidflowing through the hydrocarbon extraction system a second chemicalinjection device configured to inject the hydrate inhibitor into thefluid at a second location; wherein the controller is configured to:receive the feedback from the second sensor; determine a likelihood ofhydrate formation in the fluid at the second location based on thefeedback from the second sensor; and determine a second flow rate ofhydrate inhibitor to inject into the fluid using the second chemicalinjection device based on the likelihood of hydrate formation at thesecond location, wherein the first sensor is proximate to the firstchemical injection device and the second sensor is proximate to thesecond chemical injection device.
 8. The system of claim 1, wherein thecontroller is configured to execute a modeling program using thefeedback from the first sensor to determine the likelihood of hydrateformation.
 9. The system of claim 8, wherein the controller isconfigured to execute the modeling program to determine the flow rate ofhydrate inhibitor to inject into the fluid, wherein the modeling programis configured to determine a different flow rate of hydrate inhibitor toinject for a start-up condition of the hydrocarbon extraction system, asteady-state condition of the hydrocarbon extraction system, or ashut-in condition of the hydrocarbon extraction system.
 10. The systemof claim 1, comprising the hydrocarbon extraction system.
 11. A system,comprising: a controller configured to control an amount and timing ofinjection of a hydrate inhibitor into a hydrocarbon extraction systemusing feedback from a flow meter and a first sensor.
 12. The system ofclaim 11, wherein the controller is configured to control the injectionof the hydrate inhibitor with a chemical injection device in response tothe feedback from the flow meter and the first sensor.
 13. The system ofclaim 11, wherein the first sensor comprises a pressure sensor or atemperature sensor.
 14. The system of claim 11, wherein the controlleris configured to execute a modeling program using the feedback from theflow meter and the first sensor to determine a likelihood of hydrateformation and to control the amount and timing of the injection of thehydrate inhibitor to reduce the likelihood of hydrate formation.
 15. Amethod for managing hydrate formation in a hydrocarbon extractionsystem, comprising: receiving a flow rate from a flow meter; receivingat least one of an environmental condition and a fluid condition from afirst sensor; identifying a hydrate formation condition using feedbackfrom the flow meter and the first sensor; and controlling injection of ahydrate inhibitor in response to the hydrate formation condition. 16.The method of claim 15, wherein the environmental condition comprisestemperature, pressure, or both, and wherein the fluid conditioncomprises water content.
 17. The method of claim 16, comprising:receiving the environmental condition from the first sensor; receivingthe fluid condition from a second sensor; and identifying the hydrateformation condition using the flow rate, the environmental condition,and the water content.
 18. The method of claim 15, wherein the firstsensor comprises at least one of a pressure sensor, a temperaturesensor, a conductivity probe, and a salinity sensor.